Application of conventional thermoelectric power generation processes and equipment has involved numerous problems with respect to: undesired constituents in off gases from the combustion process; and, inefficient utilization of the heat content of the hot combustion gases. Although a variety of methods and processes have been developed to address these problems in various systems, efforts toward improvement are ongoing.
When the combustion fuel is coal, numerous problems are presented. One of these is that the combustion gases of coal include certain particularly undesirable materials therein for release to the atmosphere or which can damage downstream equipment. These include: particulates; oxidized sulfur compounds, generally referred to by their principle component, sulfur dioxide; oxides of nitrogen, typically referred to by the general formula NO.sub.x or the general term "nitrous oxides"; and, CO.sub.2, generally considered to be a greenhouse gas. In the United States, there are already controls or limits on the amounts of sulfur dioxide that can be expelled with off gases from coal combustion processes. In many foreign countries, limits have been placed on NO.sub.x emissions, and more limitations may be expected both in the United States and elsewhere in the future. In any event, regardless of governmental limitations, it is generally desirable to maintain NO.sub.x, sulfur dioxide, CO.sub.2, and particulate emissions from coal combustion processes as low as reasonably and economically possible.
Another problem with coal combustion concerns the fact that residue, i.e. bottom ash, fly ash or slag, is generated when coal is burned. Ash or slag materials are created in huge quantities from coal burning power plants, and in some instances disposal may be a problem. In general, it is preferred to maintain a combustion process such that the ash or slag resulting therefrom is nonleachable, i.e., contains little or essentially no components therein which are leachable therefrom, for example by ground water.
It is noted that carbon dioxide, a principal product of coal combustion, is a greenhouse gas. Thus, it is desirable to maintain its generation at a minimum. This can be effected in part by relatively efficient utilization of the heat energy generated from coal combustion. That is, the greater the thermal efficiency achieved from the coal combustion, the less amount of CO.sub.2 generated per energy unit generated. Of course, in general, high thermal efficiencies are desirable, and constantly sought, to improve the economic efficiency of power generation; that is, to generate more electricity at less expense in terms of fuel use.
In FIG. 1, a schematic representation of a typical coal-based power generating cycle is illustrated. During processing, combustion occurs in a boiler 1. Coal is shown fed into the boiler 1, at 2. Air, for combustion, is shown fed into boiler 1 at 3. Within the boiler 1, the coal is combusted under controlled conditions. The boiler 1 includes a heat exchanger 5 therein, with fluid such as water passing therethrough. Released heat from the combusted coal is transferred to the fluid within heat exchanger 5 (for example converting the fluid, if water, to high pressure and temperature steam). Steam flow out from the boiler 1 is indicated at 6. The steam is directed to a steam turbine 8, wherein it expands and drives a turbo generator 9, to generate power. An off steam line from the steam turbine 8, after expansion, is shown at 10. After expansion, via line 10 the steam is directed to a condenser 12 where, under low pressure, it is converted back to water which, via line 13 and by means of pump 14 is recirculated to the boiler 1. Alternatively, the steam may be extracted from the turbine to provide heat for processing or similar purposes in a cogeneration mode. Typically, it is recirculated as shown. A pump to facilitate this is shown at 14.
Combustion gases which form in the boiler 1 are generally transferred therefrom via line 15 through an economizer or preheater arrangement 16, wherein the gases are cooled to a temperature of about 250.degree.-300.degree. F. The heat drawn off from the combustion gases in heat exchanger 16 is used to preheat air directed into the boiler 1, at 3, as combustion air. Air input to the heat exchanger 16 for this purpose, is indicated at 18. The off combustion gases are shown directed via line 19 through a pollution control device 20 whereat undesired materials in the gases are removed. Off gases from the pollution control arrangement 20 are shown directed via fan 21 through stack 22, for discharge to the atmosphere.
The pollution control device 20 is utilized, in various systems, to control a variety of emissions to the atmosphere. For example, the pollution control device 20 may include a scrubber therein, for removal of sulfur dioxide in the flue gases from the boiler 1. Further, the arrangement may include a precipitator or bag house, for removal of particulates.
Although widely used, systems as shown in FIG. 1, have relatively low thermal efficiency (typically 32-35%). Reasons for this include the fact that up to about 50% of heat is lost in the condenser to cooling water, and about 5-7% of heat is lost in flue gas to the atmosphere.
While the efficiency of the cycle could be improved by utilization of more heat from the flue gas, in the past this has not been practical. In general, the flue gas passing through the heat exchange arrangement 5 and/or the air preheater 16 includes fly ash, sulfur compounds and moisture therein. If it is cooled to below about 250.degree. F., moisture condenses and, with sulfur, forms sulfuric acid. Sulfuric acid and dust deposition within equipment such as the preheater 16 would tend to cause problems with corrosion and deposits. The deposits would tend to cut, in time, efficiency of heat transfer; and the corrosion problem will eventually lead to a shorter life of the equipment.
Another reason why off gases from the boiler 1 and heat exchanger 16 are generally not cooled to much below about 250.degree. F., is that if the flue gas line 19 is cooler than this, after it passes through pollution control device 20, it may be so cool that water deposits in stack 22 may occur, or a large, thick, steam or plume cloud will tend to form immediately above stack 22. That is, in general, especially in populated areas, it is desired that the gases emitted from the stack 22 disperse significantly, before substantial condensation occurs, so that the steam cloud or plume is less of a problem. If the gases in the stack 22 are sufficiently cool, this cannot be accommodated. Therefore, in some instances, when the flue gases from the pollution control device 20 are not sufficiently warm, they are reheated during the process of passing them through the stack 22. This consumes energy, and generates greater inefficiency. Flue gas condensers could not readily be used to control moisture content in the flue gases, because they too would be subject to the problems of sulfuric acid formation.
A more efficient generation of power, with reduction of condenser heat losses, has been accomplished through so-called "combined cycle" processes. In typical conventional combined cycle processes natural gas or distillates are used as fuel. Such an arrangement is illustrated in FIG. 2.
Referring to FIG. 2, the natural gas or distillate fuel is shown fed into a combustor 30 via line 31. In combustor 30 the fuel is mixed with compressed air from line 32 (and compressor 33) and is burned under pressure, typically about 2-16 atm but sometimes higher. Hot combustion gases from the burner 30 are shown drawn off at line 35. The gases are shown directed into a gas turbine power generation arrangement including gas turbine 40. In typical operation, the hot gases from line 35 are directed into the gas turbine at temperatures of about 1800.degree.-2300.degree. F., although it is expected that in the near future gas turbine arrangements capable of handling gases up to about 3000.degree. F. will be developed. In the gas turbine 40 the gases are expanded to about atmospheric pressure, and reduced in temperature to about 800.degree.-1000.degree. F. Off gases from the turbine 40 are shown at line 41. The gas turbine 40 is shown powering generator 42, for production of electricity.
Hot exhaust gas from the turbine 40 via line 41 is then directed into a waste heat recovery system or heat recovery boiler/steam turbine power generation arrangement indicated generally at 45. More specifically, the hot gases are directed into a heat recovery boiler 46, at 47. Within heat recovery boiler 46, a heat exchange unit 48 is utilized, to derive heat from the gases, typically upon generation of steam. Steam from the heat exchange unit of the heat recovery boiler 46 is shown drawn off at line 49, and is directed to steam turbine 50. In steam turbine 50, the hot steam is expanded and cooled, to generate power via generator 51. Expanded steam output from turbine 50 is shown directed via line 52 through condenser 53, for cooling. Water output from condenser 53 is shown at line 55. The water is typically recycled to the heat recovery boiler 46, as shown at 56. Pump 58 facilitates the circulation.
The hot gases from line 41, after having been cooled in heat recovery boiler 46 are shown drawn off therefrom at line 59. The gases are then directed through fan 60 and stack 61, for dispersion to the atmosphere. Because both natural gas and distillates are clean fuels, flue gas leaving the heat recovery boiler 46, even at temperatures of about 200.degree.-250.degree. F., can be discharged to the atmosphere directly, without cleanup. Further, a relatively high degree of cooling within boiler 46 can occur, i.e. below 250.degree.-300.degree. F., since the clean fuels have little sulfur component(s) which would present sulfur acid formation problems.
Herein the term "gas turbine power generation arrangement" and variants thereof refers to an arrangement wherein power is generated by expanding a hot gas in a gas turbine. The term "heat recovery boiler/steam turbine arrangement", and variants thereof, refers to arrangements involving power generation by passing hot gases through a boiler to generate steam, and passing the steam through a steam turbine, to generate power.
In typical combined cycle systems approximately 2/3 of power is generated in the gas cycle and only about 1/3 in steam cycle. Consequently, the negative effects of heat losses in the condenser downstream of the steam turbine are reduced drastically. Modern combined cycles generally perform with thermal efficiencies close to 50%. Currently, conventional combined cycle provides approximately 30,000 MWe (megawatt) capacity worldwide.
Because coal represents approximately 90% of all fossil fuel resources, efforts have been developed to find ways for its utilization for "clean" power generation, especially so it can be used as a fuel for combined cycle power generation. For example, for the arrangement of FIG. 2, coal would not be an acceptable fuel source, since combustion gases from coal are generally too contaminated with particulates, sulfur material and nitrous oxides, to be utilized in the equipment shown, or for discharge to the atmosphere as shown.
Coal has been utilized as a source of fuel in atmospheric or pressurized fluidized bed boilers. However, low combustion temperatures of about 1550.degree. F. limit thermal efficiency of the system. That is, coal can be combusted to generate much higher temperature gases, however, they could not be accommodated by conventional fluidized bed boilers.
Limestone, which has been utilized as a sorbent for sulfur capture in fluidized bed systems, contributes to the formation of additional carbon dioxide and flue gases, and increases volume of leachable bottom ash considerably. Further, it appears that No.sub.x control and fluidized combustion systems will not satisfy new emission standards, and effectiveness of SO.sub.2 control has in the past been uncertain for combustion of high sulfur coals.
Coal gasification is a proven method for application in so-called integrated coal gasification combined cycles (IGCC). However, thermal efficiency of the cycle is limited due to cleaning of the coal gas under relatively cold conditions in wet scrubbers. Also, complexity and high costs of the systems appears to be a big barrier for applications in utility industries.
Another problem with high temperature coal gases is that they may include vaporized caustics therein, for example alkali gases from high temperature combustion of coal having alkali impurities therein. Such vapors can be very corrosive to heat transfer surfaces in the heat recovery boiler. This can lead to corrosive buildup on the heat transfer surfaces, generating reduced efficiency of heat transfer. Also, corrosive buildup necessitates increased maintenance, i.e., cleaning; and, it eventually can lead to structural failure, requiring down time and increased capital expenditure. Similar problems can result in the gas turbine as well.
The presence of sulfur dioxide and moisture in coal gas, in practice, has (as suggested above) limited the amount of heat energy that can be derived from the coal gas in the boiler. A reason for this is that if the coal gas is cooled to much below about 250.degree.-300.degree. F. (150.degree. C.) in a boiler arrangement, sulfur acid products from the gas can begin to collect on the heat recovery surfaces in the boiler arrangement. Such products are corrosive, and can damage the heat recovery surfaces, causing problems similar to those discussed above with respect to alkali corrosives. Thus, although coal gases theoretically have a heat content that could be more efficiently utilized if the gases were passed through a heat recovery boiler and were cooled to a greater extent than merely to 300.degree. F., in the past, as a practical matter, they could not be cooled to much below about 300.degree. F.
Another problem with the presence of moisture in cooled coal combustion off gases (as suggested above) concerns the eventual release of the moisture to the atmosphere. If the gases released to the atmosphere are sufficiently cool, immediately upon release to the atmosphere a large, thick, vapor cloud or "plume" will result at the top of the stack. Such large, thick, steam or vapor clouds (or plumes) are generally undesired, especially in urban areas. For this reason, in some instances it has been necessary to reheat the gases at the exhaust stack (i.e., downstream of the heat recovery boiler but prior to release to the atmosphere) to ensure greater dispersion before they cool sufficiently for substantial vapor cloud formation. This has generally necessitated significant heat input at the stack, to ensure that the gases leaving the top of the stack are at about 300.degree.-340.degree. F. (150.degree.-175.degree. C.), lessening the efficiency of overall power generation by the system.
Of course, it is theoretically possible to condense the moisture from the off gases before exhaust to the atmosphere. In the past, this has been infeasible and impractical, because such condensation would generate corrosive materials on the heat transfer surfaces of the condenser, causing similar problems to those discussed with respect to heat transfer surfaces in the heat recovery boiler.
The arrangement of FIG. 2 is generally referred to as a "combined cycle" arrangement, since two cycles for power generation are provided: a gas turbine cycle and a steam turbine cycle. Coal gas has not been utilized in many such systems, at least in part due to undesirable properties of cool gas causing problems generally similar to those discussed above with respect to conventional heat recovery boiler systems. That is, compressor and/or gas turbine arrangements are susceptible to interference from, or damage caused by, particulates and/or other constituents in hot coal gases. In fact, such equipment is generally more expensive, and more sensitive to such constituents in the gases, than are conventional heat recovery boilers.
As indicated previously, in general it is preferable to reduce or limit the amount of nitrous oxide (NO.sub.x) emitted in off gases from power generation. Nitrous oxides are formed as products in many combustion process off gases, including those from natural gas combustion. That is, among the off gases from burner 30, FIG. 2, one could expect nitrous oxide emissions. While it has generally been found that treatment of combustion gases with water at high temperatures can minimize nitrous oxide production (by reaction to nitrogen, oxygen and hydrogen) if such a process were to be conducted in the schematic of FIG. 2, the gas turbine 40 would have to be constructed and arranged to accommodate the water treatment process. Since for many gas turbine arrangements the burner forms part of the system, this would be expected to lead to an increase in the cost of preparation, design and maintenance of the gas turbine. That is, in general conventional gas turbines are not readily adaptable to such water treatment processes.
An overall schematic for a system utilizing a coal-based combined cycle has been developed; see U.S. Pat. No. 4,590,868 to Ishihara, the disclosure of which is incorporated herein by reference. In the Ishihara system, coal is combusted under pressurized conditions to generate hot pressurized off gases. The off gases are cleared of particulates via a multi-step dust removal arrangement. The pressurized gases are then directed through a combined cycle system for power generation. After power generation and before the gases are discharged into the atmosphere, they are directed through a conventional cleaning operation for scrubbing sulfur dioxide, before discharge to the atmosphere.